Investigating the effect of salt concentration on oil recovery during guar gum polymer flooding: A simulation study

Abstract

Reservoirs producing heavy crude oil (gravities <20) pose serious production challenges due to oil's highly viscous nature. The risks of optimizing oil production from these reserves to meet energy demands are more feasible than the financial requirements of venturing into newer fields. Water injection options in such reservoirs substantially affect the oil produced but are limited, especially when the reservoir fluid is more viscous than the injected water. Thermal options for heavy oil reservoirs are often discouraged due to loss of energy and the lighter portion of the hydrocarbon fluids, hence less expensive and environmentally friendlier options such as polymer flooding are encouraged. This study considers polymer injection options and the effects of salt concentrations as it affects heavy oil recovery us. Firstly, 6 wt %’s of Guar Gum (GG) (0.1, 0.2, 0.3, 0.4, 0.5, and 1.0) are diluted in 300 ml of water and the rheological properties estimated from these concentrations are used to build 6 different reservoir models (with an oil density of 20lb/ft3) in conjunction with polymer/salt keywords, rock and fluid properties using the Eclipse black oil model. Two salt concentrations are considered individually for each polymer concentration and a base case of natural production is considered. An oil recovery of 5.90 % (primary production), 30.78 % (water injection), 48.53 %, 48.74 %, 48.78 %, 49.18 %, 49.34 %, and 55.49 % are recorded under polymer flooding. An oil recovery of 55.04 % and 54.60 % is recorded at 5 % wt. and 10 % wt. Salt concentrations during 1 % wt. Polymer flooding. Increasing GG concentration will evidently increase oil recovery due to a higher viscosity index while increasing salt concentrations will reduce oil recoveries.